1. Field of the Invention
This invention relates generally to rotary drill bits used in drilling subterranean boreholes and, more specifically, to drilling structures having at least one gage portion or region which provides expansion of the diameter of a borehole beyond that drilled by cutters on the face of a drill bit to reduce loading on the cutters of the bit and to facilitate maneuvering of the drill bit down hole.
2. State of the Art
The equipment used in subterranean drilling operations is well known in the art and generally comprises a drill bit attached to a drill string, including a drill pipe and one or more drill collars. A rotary table or other device such as a top drive is used to rotate the drill string, resulting in a corresponding rotation of the drill bit. The drill collars, which are heavier per unit length than drill pipe, are normally used on the bottom part of the drill string to add weight to the drill bit, increasing weight on bit (WOB). The weight of these drill collars presses the drill bit against the formation at the bottom of the borehole, causing it to engage the formation and drill when rotated. Downhole motors are also normally employed in the drilling of directional or oriented boreholes, in which case the bit is secured to the output or drive shaft of the motor.
A typical rotary drill bit includes a bit body with a structure for connecting the bit body to the drill string, such as a threaded portion on a shank extending from the bit body, and a crown comprising that part of the bit fitted with cutting structures for cutting into a subterranean formation. Generally, if the bit is a fixed-cutter or so-called "drag" bit, the cutting structures include a series of cutting elements (also termed cutters) made of a superabrasive material, such as polycrystalline diamond, oriented on the bit face at an angle to the surface being cut (i.e., side rake, back rake).
Various manufacturing techniques known in the art are used for making a drill bit. In general, the bit body may typically be formed from a cast or machined steel mass, or comprise a tungsten carbide matrix cast by infiltration in a mold cavity with a liquified metal binder and secured thereby to a blank extending into the matrix, the blank being subsequently welded to a tubular shank. Threads are then formed onto the free end of the shank to correspondingly match the threads of a drill collar.
Cutting elements are usually secured to the bit by preliminary bonding to a carrier element, such as a stud, post or elongated cylinder, which, in turn, is inserted into a pocket, socket or other aperture in the crown of the bit and mechanically or metallurgically secured thereto. Specifically, polycrystalline diamond compact (PDC) cutting elements, usually of a circular or disc-shape comprising a diamond table bonded to a supporting WC substrate, may be brazed to a matrix-type bit after furnacing. Alternatively, freestanding (unsupported), metal-coated, thermally stable PDCs (commonly termed TSPs) may be bonded into the bit body during the furnacing process used to fabricate a matrix-type drill bit. Natural diamonds may also be used as cutters and, as with TSPs, bonded into a bit body.
The direction of the loading applied to the radially outermost (i.e., gage) cutters in conventional drill bits is primarily lateral. Such loading is thus tangential in nature, as opposed to the force on the cutters on the face of the bit, which is substantially provided by the WOB and thus comprises a normal force substantially in alignment with the longitudinal axis of the bit. The tangential forces tend to unduly stress even those cutters specifically designed to accommodate this type of loading because of the stress concentrations experienced by the relatively small number of cutters assigned the task of cutting the gage diameter. It should be realized that, for any given rotational speed of a bit, the cutters proximate the gage area of the bit are traveling at the highest velocities of any cutters on the bit due to their location at the largest radii of the bit. Such cutters also traverse the longest distances during operation of the bit. Therefore, their velocity, plus their distance traveled and the large sideways or lateral resistive loads encountered by the cutters, may overwhelm even the most robust state-of-the-art superabrasive PDC cutters. The radially outermost cutters on the bit face, referred to as gage cutters, typically have a flattened or linear radially outer profile aligned parallel to the longitudinal axis of the bit to reduce cutter exposure and to cut a precise gage diameter through the borehole. Such profiles, unfortunately, actually enhance or accelerate wear in the cutters due to the large contact areas of the cutters with the formation, which generate excessive heat. Wear of the gage cutters may, over time, result in an undergage wellbore.
In a conventional bit arrangement, the gage of the bit is that substantially cylindrical portion located adjacent to and extending above the gage cutters longitudinally along the bit body at a given, fixed radius from the bit centerline, the gage of the bit body being parallel to the bit centerline. In a slick gage arrangement, for example, such as that disclosed in U.S. Pat. No. 5,178,222, the radius of the gage is essentially the same as the outer diameter defined by the gage cutters. During drilling, as the bit penetrates into a formation, a typical drill bit will drill the borehole diameter with the gage cutters. The gage of the bit then snugly passes through the borehole. Even when the gage cutters extend a substantial radial distance from the centerline beyond the gage of the bit, as the gage cutters wear and the diameter of the wellbore consequently decreases to become closer to that of the bit gage, greater frictional resistance by the gage against the wall of the wellbore is experienced. As a result, the rate of penetration (ROP) of the drill bit will continually decrease, requiring application of increasing torque to the bit until the gage cutters degrade to a point where the ROP is unacceptable. At that point, the worn bit must be tripped out of the borehole and replaced with a new one, even though the face cutting structure may be relatively unworn.
These problems are somewhat addressed by, for example, providing cutting elements on the gage of the bit to lengthen the life of the drill bit. For example, U.S. Pat. No. 5,467,836 discloses a drill bit having gage inserts that provide an active cutting gage surface which engages the sidewall of the borehole to promote shearing removal of the borehole sidewall material. U.S. Pat. No. 5,004,057 illustrates a drill bit having both an upper and lower gage section having gage cutting portions located thereon. Other prior art bits include both abrasion-resistant pads and cutters on the gage of the bit, such as the bit disclosed in U.S. Pat. No. 5,163,524. An approach to providing an increased enlargement of the borehole is disclosed, for example, in U.S. Pat. No. 3,367,430 and U.S. Pat. No. 5,678,644, each of which describes an upper eccentric gage portion which cuts a larger portion of the formation above a lower gage portion of the drill bit. Neither design, however, is structured for reducing cutting loads on the gage cutters, nor do they provide an increase in the borehole diameter immediately above the gage cutters.
Recognizing that conventional bit body designs may place the gage cutters in a position on the bit which leads to early bit failure, and further recognizing that the design of the typical bit gage makes it difficult to maneuver the bit downhole once the gage cutters are worn, it would be advantageous to provide a drill bit which is configured to provide a slight enlargement of the borehole diameter to lessen the loads on the gage cutters and to facilitate maneuvering of the drill bit downhole.